Note: Descriptions are shown in the official language in which they were submitted.
PAT 104084-1
PROCESS FOR REMOVING SCALE IN A STEAM GENERATOR
FOR USE IN HYDROCARBON RECOVERY
Technical Field
[0001] The present invention relates to steam generators utilized to
produce
steam for injection into an underground reservoir to mobilize hydrocarbons
such as
heavy oils and bitumen.
Background
[0002] Extensive deposits of viscous hydrocarbons exist around the world,
including large deposits in the northern Alberta oil sands that are not
susceptible to
standard oil well production technologies. The hydrocarbons in reservoirs of
such
deposits are too viscous to flow at commercially relevant rates at the
temperatures
and pressures present in the reservoir. For such reservoirs, thermal
techniques
may be utilized to heat the reservoir to mobilize the hydrocarbons and produce
the
heated, mobilized hydrocarbons from wells. One such technique for utilizing a
horizontal well for injecting heated fluids and producing hydrocarbons is
described
in U.S. Patent No. 4,116,275, which also describes some of the problems
associated
with the production of mobilized viscous hydrocarbons from horizontal wells.
[0003] One thermal method of recovering viscous hydrocarbons using spaced
horizontal wells is known as steam-assisted gravity drainage (SAGD). In the
SAGD
process, pressurized steam is delivered through an upper, horizontal,
injection well
(injector), into a viscous hydrocarbon reservoir while hydrocarbons are
produced
from a lower, parallel, horizontal, production well (producer) that is near
the
injection well and is vertically spaced from the injection well. The injection
and
production wells are typically situated in the lower portion of the reservoir,
with the
producer located close to the base of the hydrocarbon deposit to collect the
hydrocarbons that flow toward the base of the deposit.
[0004] The SAGD process is believed to work as follows. The injected steam
initially mobilizes the hydrocarbons to create a steam chamber in the
reservoir
around and above the horizontal injection well. The term steam chamber is
utilized
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to refer to the volume of the reservoir that is saturated with injected steam
and
from which mobilized oil has at least partially drained. As the steam chamber
expands, viscous hydrocarbons in the reservoir and water originally present in
the
reservoir are heated and mobilized and move with aqueous condensate, under the
effect of gravity, toward the bottom of the steam chamber. The hydrocarbons,
the
water originally present, and the aqueous condensate are typically referred to
collectively as emulsion. The emulsion accumulates such that the liquid /
vapor
interface is located below the steam injector and above the producer. The
emulsion
is collected and produced from the production well. The produced emulsion is
separated into dry oil for sales and produced water, comprising the water
originally
present and the aqueous condensate.
[0005] Steam that is injected into the reservoir through the injection
well may
be recycled by reheating the produced water that is produced from the wells in
a
steam generator, such as a once through steam generator (OTSG), and again
injecting the steam into the reservoir. Accumulation of contaminants and the
formation of scale on tubes within the steam generator is a problem, even
after
treatment of the produced water in a series of processes including, but not
limited
to skimming, flotation, oil filtering, warm lime softening, lime softener
filtration,
and primary strong acid and secondary weak acid ion exchange processes prior
to
feeding to the steam generator. Such processes may be beneficial to remove
oil,
silica, calcium, magnesium, and iron prior to passing treated produced water
through the steam generator, but scale buildup on the inside of the tubes of
the
steam generator remains an issue. Scaling of the tubes of the steam generator
reduces heat transfer and decreases the efficiency of the steam generator, and
increases the cost of operating the steam generator.
[0006] Methods utilized for cleaning a steam generator, such as operating
a
pig (a device passed through the tubing for cleaning and/or inspection) within
the
steam generator, are time consuming, costly, and take the steam generator
offline
for many days per year.
[0007] Improvements in scale removal from the tubes in such steam
generators are desirable.
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Summary
[0008] According to an aspect of an embodiment, there is provided a
process
for removing scale in a steam generator for use in a hydrocarbon recovery
process.
The process for removing scale includes introducing feed water into the steam
generator and introducing particles and pressurized gas into the steam
generator,
at a pressure sufficient to cause turbulent flow of fluid including the feed
water, the
gas, and the particles, for removing scale from interior walls of tubes of the
steam
generator, wherein the particles have a sufficient hardness to remove the
scale
without damaging the tubes beyond a threshold associated with safe operation
of
the steam generator.
[0009] The particles may have a hardness greater than the hardness of the
scale, the tubes, or both the scale and the tubes. The particles maybe
thermally
stable up to a temperature of at least 100 C and, optionally, up to at least
180 C.
[0010] The particles and the feed water may be introduced into the steam
generator at a temperature of about 180 C.
[0011] The particles and the scale may be separated from the fluid.
Optionally, steam may be produced in the steam generator and the steam
separated prior to or after separating the particles and the scale from the
fluid. The
particles and the scale may be disposed of in a disposal receptacle in fluid
communication with the steam generator.
[0012] The particles and pressurized gas may be introduced into the
vessel
and introduced into the steam generator from the vessel. The particles and
pressurized gas may be introduced into the feed water prior to introducing the
feed
water and introducing the particles and pressurized gas into the steam
generator.
The particles may be introduced into a carrier solution, such as distilled
water or
methanol, in the vessel.
[0013] The particles may be glass, metal, ceramic, or a combination
thereof.
For example, the particles may be cut wire. The pressurized gas may be
nitrogen
or propane. Alternatively, the pressurized gas may comprise oxygen.
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[0014] A differential pressure may be monitored across at least a part of
the
steam generator during steam production and prior to introducing the particles
and
the pressurized gas, and the particles and the pressurized gas may be
introduced in
response to detecting a change in the differential pressure that exceeds a
threshold.
[0015] Blocking of steam sampling lines from the steam generator by scale
removed from the tubes of the steam generator may be inhibited by one of
shutting
in the steam sampling lines, creating a backflow of fluid in the steam
sampling
lines, and purging the steam sampling lines utilizing a blow-off connection to
a
blowdown tank.
[0016] According to another aspect, a system for producing steam for use
in a
hydrocarbon recovery process to recover hydrocarbons from a hydrocarbon
reservoir is provided. The system includes a steam generator that has an
economizer section for preheating feed water, a radiant section in fluid
communication with the economizer section for generating steam from the feed
water, and at least one inlet for receiving pressurized gas and particles into
the
economizer section to create turbulent flow of fluid including the feed water,
the
gas, and the particles, for removing scale from interior walls of tubes of the
steam
generator. The particles have a sufficient hardness to remove the scale
without
damaging the tubes beyond a threshold associated with safe operation of the
steam
generator. The system also includes a separator in fluid communication with
the
steam generator for separating the steam generated from the feed water for use
in
hydrocarbon recovery.
Brief Description of the Drawings
[0017] Embodiments of the present invention will be described, by way of
example, with reference to the drawings and to the following description, in
which:
[0018] FIG. 1 is a sectional view through a reservoir, illustrating a SAGD
well
pair;
[0019] FIG. 2 is a sectional side view illustrating a SAGD well pair
including an
injection well and a production well;
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[0020] FIG. 3 is a simplified schematic view illustrating a system and
process
for removing scale in a steam generator utilized in a hydrocarbon recovery
process
in accordance with an example;
[0021] FIG. 4 is a simplified schematic view illustrating a system and
process
for removing scale in a steam generator utilized in a hydrocarbon recovery
process
in accordance with another example;
[0022] FIG. 5 is a simplified schematic view illustrating a system and
process
for removing scale in a steam generator utilized in a hydrocarbon recovery
process
in accordance with yet another example;
[0023] FIG. 6 is a simplified schematic view illustrating a system and
process
for removing scale in a steam generator utilized in a hydrocarbon recovery
process
in accordance with yet a further example.
Detailed Description
[0024] For simplicity and clarity of illustration, reference numerals may
be
repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples
described herein. The examples may be practiced without these details. In
other
instances, well-known methods, procedures, and components are not described in
detail to avoid obscuring the examples described. The description is not to be
considered as limited to the scope of the examples described herein.
[0025] The disclosure generally relates to a system and process for
removing
scale in a steam generator utilized in a hydrocarbon recovery process. The
process
for removing scale includes introducing feed water into the steam generator
and
introducing particles and pressurized gas into the steam generator, at a
pressure
sufficient to cause turbulent flow of fluid including the feed water, the gas,
and the
particles, for removing scale from interior walls of tubes of the steam
generator,
wherein the particles are thermally stable up to a temperature of at least 100
C.
[0026] Reference is made herein to an injection well and a production
well.
The injection well and the production well may be physically separate wells.
Alternatively, the production well and the injection well may be housed, at
least
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partially, in a single physical wellbore, for example, a multilateral well.
The
production well and the injection well may be functionally independent
components
that are hydraulically isolated from each other, and housed within a single
physical
wellbore.
[0027] As described above, a steam-assisted gravity drainage (SAGD)
process
may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a
well
pair, including a hydrocarbon production well and a steam injection well are
utilized. One example of a well pair is illustrated in FIG. 1 and an example
of a
hydrocarbon production well 100 and injection well 108 is illustrated in FIG.
2. The
hydrocarbon production well 100 includes a generally horizontal segment 102
that
extends near the base or bottom 104 of the hydrocarbon reservoir 106. The
injection well 108 also includes a generally horizontal segment 110 that is
disposed
generally parallel to and is spaced generally vertically above the horizontal
segment
102 of the hydrocarbon production well 100.
[0028] During SAGD, steam is injected into the injection well 108 to
mobilize
the hydrocarbons and create a steam chamber 112 in the reservoir 106, around
and above the generally horizontal segment 110. In addition to steam injection
into the steam injection well, light hydrocarbons, such as the C3 through C10
alkanes, either individually or in combination, may optionally be injected
with the
steam such that the light hydrocarbons function as solvents in aiding the
mobilization of the hydrocarbons. The volume of light hydrocarbons that are
injected is relatively small compared to the volume of steam injected. The
addition
of light hydrocarbons is referred to as a solvent aided process (SAP).
Alternatively,
or in addition to the light hydrocarbons, various non-condensing gases, such
as
methane or carbon dioxide, may be injected. Viscous hydrocarbons in the
reservoir
are heated and mobilized and the mobilized hydrocarbons drain under the effect
of
gravity. Fluids, including the mobilized hydrocarbons along with connate water
and
condensed steam (aqueous condensate), are collected in the generally
horizontal
segment 102. The fluids may also include gases such as steam and production
gases (e.g., methane, hydrogen sulfide) from the SAGD process.
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[0029] The steam may be generated at least partially from the produced
water, for example, recovered from the production well 100. The produced
water,
however, includes contaminants such as oil, silica, calcium, magnesium, and
iron.
[0030] A simplified schematic illustrating a system and process for
removing
scale in a steam generator utilized in a hydrocarbon recovery process is shown
in
FIG. 3.
[0031] Water is pumped through, for example, a pump assembly 302 to
introduce the feed water 308 at high pressure into a steam generator 304,
which in
the present example is a once through steam generator (OTSG). The steam
generator 304 includes multiple tubes, referred to as passes, for heat
exchange to
heat the feed water and generate steam. The feed water 308 may include
recycled
water produced from the hydrocarbon recovery process or, for example, another
hydrocarbon recovery process occurring in another reservoir, fresh water,
water not
previously utilized in the hydrocarbon recovery process, or a combination
thereof.
[0032] Although not illustrated in FIG. 3, the produced emulsion from a
production well, such as the production well 100, may be subjected to known
separation and degassing techniques, to separate produced water from
hydrocarbons in the emulsion and from produced gas. The produced water from
the production well 100 is optionally treated in a de-oiling and water
treatment sub-
system to remove or reduce oil in the produced water. The de-oiling process
may
be, for example, a known mechanical de-oiling process followed by oil
filtering.
Produced water de-oiling may include treatment in a skim tank, an Induced Gas
Flotation (IGF) Unit or an Induced Static Flotation (ISF) Unit, and use of an
Oil
Removal Filter (ORF). The produced water may also be treated in an evaporator,
lime softener (e.g., warm lime softener (WLS), hot lime softener), or ion
exchange
equipment (e.g., Strong Acid Cation (SAC) exchange, Weak Acid Cation (WAC)
exchange). The produced water may optionally be subjected to additional
treatment processes such as electro-flocculation, column flotation, other oil
removal
or filtration processes, upset recovery, hydrocyclone treatment, graphene
membrane separation processes, capacitive deionization, ceramic membrane
filtration, and other processes, or a combination of the above processes.
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[0033] The steam generator 304 includes an economizer, also referred to as
the convective section, for preheating the feed water 308 received from the
pump
assembly 302, and a radiant section in fluid communication with the economizer
section for generating steam from the feed water.
[0034] In the present example, a vessel 306 is in fluid communication with
the feed water for introducing particles 310 and a pressurized gas 312 into
the feed
water prior to receipt of the feed water in the steam generator 304. The
vessel 306
may be, for example, a particle blowcase.
[0035] A carrier solution 311, for example, of distilled water, acid,
methanol,
or any other suitable solution, is fed to the vessel 306. The particles 310
are
introduced to the vessel 306, into the carrier solution. The particles 310 may
be
any suitable particles that are thermally stable up to a temperature of at
least
100 C. The particles 310 may be thermally stable up to a temperature of at
least
180 C. The particles may be, for example, glass, metal, ceramic, or a
combination
thereof. One example of suitable particles is cut or chopped wire. The cut
wire is
utilized as a scouring medium within the tubes of steam generator 304. The
particles 310 may have a hardness that is greater than the hardness of the
metal
tubes utilized in the steam generator 304 for removing the scale away from the
metal tubes. Optionally, the particles 310 may have a hardness that is greater
than that of the scale to remove the scale from the inner walls of the metal
tubes of
the steam generator 304. The tubes may have a hardness of about 4 to about 4.5
on the Mohs hardness scale. The hardness of the scale on the tubes may vary
depending on the source of the water and the reservoir. The hardness of the
scale
on the tubes may be about 7 on the Mohs hardness scale.
[0036] The hardness of the particles may be selected based on bond
strength
of the scale to the tubes. For example, the hardness of the particles may be
selected based on data from scale sample x-ray diffraction or other analyses
of the
steam generator that show the scale to be more or less strongly affixed (e.g.,
caked on) to the tubes. For example, if analysis of the tubes shows that the
scale is
more strongly affixed, particles of a greater hardness may be utilized.
Alternatively,
if analysis of the tubes shows that the scale is present but less strongly
affixed, for
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example, already partially dislodged, particles of a lesser hardness may be
utilized.
In an embodiment, the particles may have a sufficient hardness to remove the
scale without damaging the tubes beyond a threshold associated with safe
operation of the steam generator. A threshold associated with safe operation
of the
steam generator may be a temperature threshold or a pressure threshold. For
example, for a typical ASTM SA106B/C high pressure seamless steel tube the
carbonization temperature limit is about 427 C, above which carbonization of
the
tube walls may occur leading to a reduction of the wall stresses that the tube
can
withstand. Accordingly, operating above this carbonization temperature limit
leads
to a greater likelihood of failure of the tubes. The applicable threshold
temperature
may thus be a temperature that is lower than the carbonization temperature
limit
for the tubing, to provide an operating margin. In another embodiment the
tubes
may comply with ASTM A 335 P22 specification, and are able to withstand high
operating stress at temperatures of up to about 454 C before allowable
stresses
begin to reduce with increasing temperatures above 454 C. A temperature
threshold of about 400 C may be utilized to provide a safe operating margin.
[0037] Pressurized gas 312, such as nitrogen, methane, propane, or any
other suitable pressurized gas is also introduced into the vessel 306. Any non-
condensable gas, or condensable gas in vapour form at the operating
temperature
and pressure of the steam generator during the process for removing scale, may
be
utilized. The pressurized gas 312 is utilized to create turbulent flow within
the
steam generator 304 when the pressurized gas 312, the particles 310, and the
carrier solution flow through the steam generator 304, along with the feed
water
308, during the process of removing scale in the steam generator 304. A gas
fraction of about 30% to 90% may be suitable for removing scale in the steam
generator 304. Optionally, the pressurized gas 312 may be oxygen or air.
Because
the time during which the process of removing scale is carried out is
relatively
short, for example, about 2 hours, oxygen or air may be utilized as the time
during
which corrosion of the tubes of the heat exchanger may occur is limited.
[0038] Optionally, turbulent flow may be created within the steam
generator
304 during the process of removing scale when the particles 310 and the
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pressurized gas 312 are introduced into the steam generator 304 in the absence
of
the carrier solution and the feed water.
[0039] Optionally, turbulent flow may be created within the steam
generator
304 during the process of removing scale when the particles 310, and the
carrier
solution 311, the feed water 308, or both the carrier solution 311 and the
feed
water 308, are introduced into the steam generator 304 in the absence of a
pressurized gas.
[0040] Fluid 314 from the steam generator 304 flows to a steam separator
316. During a hydrocarbon recovery process, steam is separated from the
remaining fluid to produce dry steam 318. The remaining fluid, which may be
referred to as blowdown 320, may be subjected to filtering prior to disposal
or
further treatment to allow for recycling as boiler feed water for steam
generation.
A heat recovery process may be utilized to recover waste heat from blowdown
320
or other waste heat streams produced at the hydrocarbon recovery facility. Dry
steam 318 produced from the steam separator 316 is transported via pipeline
for
injection into the underground reservoir to mobilize the hydrocarbons during
hydrocarbon recovery.
[0041] In the example of a process for removing scale as illustrated in
FIG. 3,
the blowdown 320 is subjected to filtering in a hydrocyclonic filter 322 that
is in
fluid communication with the steam separator 316 for filtering out water 324
(referred to herein as clean blowdown) from the blowdown 320. The clean
blowdown 324 may be disposed of or further treated to allow for recycling as
BFW
for steam generation, for example, by recycling the clean blowdown 324 to the
pump assembly 302. A small volume, for example, about 2% to about 20% of the
volume of blowdown 320, is recovered by the hydrocyclonic filtering. Other
filters
may be utilized.
[0042] The hydrocyclonic filter 322 may optionally be in fluid
communication
with a basket filter 326, or other porous filter. The basket filter 326 is for
filtering
out the particles 310 from the small volume of scale and particle blowdown 328
separated from the clean blowdown 324 and drained off by and received from the
hydrocyclonic filter 322. After basket filtering, which is utilized to trap
the particles
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310 while leaving the scale with the resultant sludge, the scale and resultant
sludge
330 flows to an optional flash tank 332, to flash off additional water, thus
thickening the sludge, prior to disposal of the thickened sludge 334.
[0043] Various valves are utilized for controlling fluid flow and
monitoring
equipment is utilized for monitoring pressure and temperature throughout the
process illustrated in FIG. 3.
[0044] During steam generation for use in hydrocarbon recovery, absent the
process for removing scale, the feed water 308 is pumped through the pump
assembly 302 and introduced at high pressure into the steam generator 304. The
fluid 314 from the steam generator 304, which includes steam and remaining
fluid
(including liquid water and contaminants), flows to the steam separator 316.
The
steam is separated from the remaining fluid to produce the dry steam 318 that
is
transported via pipeline for injection into the underground reservoir. The
blowdown
320 is subjected to filtering prior to disposal or further treatment to allow
for
recycling as BFW for steam generation, for example, by recycling back to the
pump
assembly 302.
[0045] During steam generation, several parameters may be monitored and
utilized to indicate scale build-up. Increased differential pressure across
the
economizer, also referred to as the convective section, radiant section, or
entire
steam generator may indicate scale build-up. Increased differential
temperature
between the feed water at the inlet and steam generator stack exhaust
temperature may indicate scale build-up. Increased tube wall temperatures may
also indicate scale build-up. The process for removing scale may be initiated
in
response to an indication of scale build-up, such as increases in differential
pressures, increases in differential temperatures, increased tube wall
temperatures,
or on a regular schedule. The differential pressures, differential
temperatures, and
tube wall temperature changes at which the process for removing scale is
initiated
are dependent on the operating range of the steam generator.
[0046] The fire in the steam generator may be reduced, referred to as a
low
fire condition, or extinguished, referred to as a no fire condition, by
reducing or
discontinuing a feed of combustion fuel.
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[0047] In the process for removing scale as illustrated in FIG. 3, the
carrier
solution 311 is fed to the vessel 306 and the particles 310 are manually
introduced
to the vessel 306, into the carrier solution. The pressurized gas 312 is also
introduced into the vessel 306 and the carrier solution 311, the particles
310, and
the pressurized gas 312 are introduced into the feed water 308 prior to
introduction
of the feed water 308 into the steam generator 304.
[0048] The process of removing scale refers to introduction and flow of
the
mixture of pressurized gas 312, the particles 310, the carrier solution 311
along
with the feed water 308 through the steam generator. The pressurized gas 312
is
utilized to create turbulent flow within the steam generator 304 when the
pressurized gas 312, the particles 310, and the carrier solution 311 flow
through
the steam generator 304, along with the feed water 308. The pressure, and thus
the rate of flow, of the pressurized gas 312 is selected to provide a target
Reynolds
number for turbulent flow and dynamic pressure of from about 15,000 lb/ft2
(718
kPa) to about 60,000 lb/ft2 (2873 kPa) within the tubes of the steam generator
to
facilitate scale removal from the interior walls of the tubes of the steam
generator
304. For example, a dynamic pressure of about 30,000 lb/ft2 (1436 kPa) may be
targeted. Thus, the turbulent flow caused by the introduction of the
pressurized
gas, strikes the particles against the interior walls of the steam generator
304 to
scour off the interior walls of the steam generator 304 without excessive wear
of
the tubes of the steam generator 304. The feed water 308, along with the
particles
310 and the pressurized gas 312 may be introduced into multiple tubes of the
steam generator 304 simultaneously or may be introduced into the tubes, one at
a
time. There may be one process for removing scale per steam generator pass or
there may be one process for removing scale that is utilized serially on each
pass.
[0049] As indicated above, the particles 310 are thermally stable up to a
temperature of at least 100 C and may be thermally stable up to a temperature
of
at least 180 C such that the particles are thermally stable and still useful
for
removing scale in the steam generator, which may still be hot during scale
removal.
The particles have a sufficient hardness to remove the scale without damaging
the
tubes beyond a threshold associated with safe operation of the steam
generator.
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[0050] As indicated above, the process for removing scale may be
initiated in
response to an indication of scale build-up, such as increases in differential
pressures, increases in differential temperatures, increased tube wall
temperatures,
or on a regular schedule. Sufficient scale may be removed when an acceptable
range of differential pressures, differential temperatures, or wall
temperatures is
achieved during operation of the steam generator. Experimentation may be
carried
out to determine suitable particle hardness and time during which the process
for
removing scale is carried out.
[0051] The differential pressures, differential temperatures, and/or wall
temperatures post the process for removing scale may be utilized as a baseline
for
monitoring for subsequent increases in one or more of these measurements,
which
may once again trigger implementation of the process for removing scale. This
cycle may be repeated, for example, for as long as steam generation is
required for
hydrocarbon recovery. For example, for a 250 MM BTU/h OTSG, an increase in
differential pressure from a baseline of about 1,500 kPag by up to about 300
kPag or
higher, an increase in differential temperature from a baseline of about 20 C
(between the feed water at the inlet and steam generator stack exhaust) by up
to
about 10 C or higher, and/or an increase in tube wall temperature from a
baseline
of about 350 C by up to about 50 C or higher may indicate scale build-up and
embodiments of the process for removing scale may be initiated as described
herein. A person of skill in the art will appreciate that boilers of a
different size or
type may have different normal and maximum operating ranges and indications of
scale build-up may likewise be different prior to initiating the process for
removing
scale.
[0052] An indication that sufficient scale has been removed may be a
decrease in differential pressure, differential temperature, and/or tube wall
temperature. For example, differential pressure, differential temperature,
and/or
tube wall temperature may decrease to within a percentage of the baseline
measurements for these parameters (e.g., about 0-10% or within a percentage
that facilitates scale removal without damaging the tubes beyond a threshold
associated with safe operation of the steam generator as discussed herein).
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[0053] In addition to the carrier solution, the pressurized gas, and the
particles, other chemicals may be added for the purpose of descaling. For
example,
acid, chelant, silica inhibitor, and others may be added depending on the
particular
reservoir, water and facility.
[0054] Because the steam generator is operated under low or no fire
conditions, little or no steam is generated in the steam generator 304 during
the
process for removing scale.
[0055] Steam samples 313 are taken from steam sampling lines to sample
the fluid 314 from the steam generator 304. The steam samples are generally
taken for the purpose of testing the quality of the steam generated. During
the
scale removal process, such steam lines may become blocked as a result of
scale
travelling into the sampling lines. To reduce the chance of blocking the steam
sampling lines, the sample lines may be shut in or blocked to stop flow during
the
scale removal process. Alternatively, a blow-off connection to a blowdown tank
may be utilized to purge the sampling lines. In yet another alternative, a
gas, such
as nitrogen, propane, methane, or any other suitable gas, or a liquid, may be
introduced through the sampling lines to create a backflow and thereby inhibit
flow
out the sampling lines.
[0056] The fluid 314 from the steam generator 304 flows to the steam
separator 316. During the process for removing scale, little or no steam is
separated and the remaining fluid, which may be referred to as blowdown 320,
continues to the hydrocyclonic filter 322 that is in fluid communication with
the
steam separator 316 for filtering out clean blowdown 324 from the blowdown 320
and disposal or further treatment of the clean blowdown 324 to allow for
recycling
as BFW for steam generation, for example, by recycling to the pump assembly
302.
The small volume of fluid drained off from the hydrocyclonic filter 322, which
includes the particles and scale, is optionally received in the basket filter
326 and
the particles 310 are filtered out. Optionally, the particles 310 may be
reused one
or more times for removing scale in the steam generator 304. Alternatively,
the
particles may be discarded. After optional thickening in the flash tank 332,
the
thickened sludge 334, including the scale, is disposed of.
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[0057] In the example described above, the steam generator 304 is operated
under low or no fire conditions during the scale removal process.
Alternatively, the
scale removal process may be carried out while the steam generator 304 is
operated such that some steam is generated without creating excessive dynamic
pressure in the steam generator which may cause accelerated tube erosion.
[0058] The scale removal process may be carried out each month in a short
period of time. For example, the process may be carried out once each month
and
may be carried out in about 2 hours.
[0059] A simplified schematic illustrating another example of a system and
scale removal process in a steam generator utilized in a hydrocarbon recovery
process is shown in FIG. 4. The system of FIG. 4 includes many elements that
are
similar to those of FIG. 3. Many of the similar elements are not described
again in
detail.
[0060] Water is pumped through, for example, the pump assembly 302 to
introduce the feed water 308 at high pressure into the steam generator 304.
The
steam generator 304 includes an economizer for preheating the feed water 308
received from the pump assembly 302, and a radiant section in fluid
communication
with the economizer section for generating steam from the feed water.
[0061] A vessel 306 is in fluid communication with the feed water for
introducing particles and pressurized gas into the feed water prior to receipt
of the
feed water in the steam generator 304. The vessel 306 may be, for example, a
particle blowcase. The particles 310 are introduced to the vessel 306, into
the
carrier solution (not shown). Pressurized gas 312 is also introduced into the
vessel
306 and the pressurized gas 312 is utilized to create turbulent flow within
the
steam generator 304 when the pressurized gas 312, the particles 310, and the
carrier solution flow through the steam generator 304, along with the feed
water
308.
[0062] In the present example, fluid 314 from the steam generator 304
flows
to the steam separator 316 during a hydrocarbon recovery process and steam is
separated from the remaining fluid to produce dry steam 318. The remaining
fluid,
which may be referred to as blowdown 320, is disposed of.
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[0063] During the scale removal process however, fluid from the steam
generator 304 does not flow to the steam separator 316. Instead, the fluid
314,
including the scale and particles 310, from the steam generator 304 is
directed to a
disposal receptacle such as a pond or other disposal site 440.
[0064] In the example illustrated in FIG. 4. The fluid from the steam
generator 304 is directed to the steam separator 316 during the hydrocarbon
recovery process, and is disposed of during the process for removing scale.
[0065] During the steam generation for use in hydrocarbon recovery,
without
the process for removing scale, the feed water 308 is pumped through the pump
assembly 302 and introduced at high pressure into the steam generator 304. The
fluid 314 from the steam generator 304, which includes steam and water, flows
to
the steam separator 316. The steam is separated from the remaining fluid to
produce the dry steam 318 that is transported via pipeline for injection into
the
underground reservoir. The blowdown 320 is disposed of, as described above.
[0066] In the scale removal process, the fire in the steam generator may
be
reduced, referred to a low fire condition, or extinguished, referred to as no
fire by
reducing or discontinuing a feed of combustion fuel.
[0067] The carrier solution is introduced to the vessel 306 and the
particles
310 are manually introduced to the vessel 306, into the carrier solution. The
pressurized gas 312 is also introduced into the vessel 306 and the carrier
solution,
the particles 310, and the pressurized gas 312 are introduced into the feed
water
308 from the pump assembly 302, prior to introduction into the steam generator
304. The turbulent flow caused by the introduction of the pressurized gas,
pounds
the particles against the interior walls of the steam generator 304 to scour
of the
interior walls of the steam generator 304 without excessive wear of the tubes
of the
steam generator 304. Fluid 314 from the steam generator 304, including the
particles and the scale is disposed of.
[0068] In an alternative embodiment, the pressurized gas 312 and the
particles 310 are introduced into the feed water 308, with the carrier
solution being
optional.
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[0069] A simplified schematic illustrating still another example of a
system
and process for removing scale in a steam generator utilized in a hydrocarbon
recovery process is shown in FIG. 5. The system of FIG. 5 is similar to the
system
of FIG. 4 and is therefore not described again in its entirety. In the example
shown
in FIG. 5, however, the particles 310 are introduced into a carrier solution
in a
vessel, which in this example is a fluid tank 506. The carrier solution and
the
particles are together pumped, via a pump 550, into the feed water 308, prior
to
introduction of the feed water 308 into the steam generator 304. Pressurized
gas
312, is fed from a pressurized gas storage vessel 552 into the feed water 308,
prior
to introduction of the feed water into the steam generator 304. Thus, in the
present example, the particles 310 and carrier solution are introduced into
the feed
water 308 separate of the introduction of the pressurized gas 312 into the
feed
water 308.
[0070] The remaining elements of the present example are similar to those
described with reference to FIG. 4 and are therefore not further described
herein.
[0071] A simplified schematic view of yet a further example of a system
and
process for removing scale in a steam generator utilized in a hydrocarbon
recovery
process is shown in FIG. 6. The system of FIG. 6 is similar to the system of
FIG. 4
and is therefore not described again in its entirety. In the example shown in
FIG.
6, however, the particles 310 are introduced into an eductor 606 that is
utilized to
introduce the particles into the feed water 308, prior to introduction of the
feed
water 308 into the steam generator 304.
[0072] A motive fluid 654 is utilized with the eductor 606 to pump the
particles 310 into the feed water 308. The motive fluid may be, for example,
boiler
feed water, as is illustrated in the line 656 extending from the feed water
308,
through a flow control valve (FCV) 658 and into the eductor 606.
Alternatively,
other motive fluids may be utilized, such as brackish water, blowdown water,
air,
nitrogen, or other gases. Optionally an acid, such as HCI, or a base, such as
NaOH,
may be mixed with boiler feed water, brackish water, or blowdown water for use
as
the motive fluid 654.
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[0073] The particles 310 are introduced into the eductor 606,
via the eductor
suction. The particles 310 may include, for example cut wire, ceramic balls,
sand,
or other particles in air. The particles 310 may alternatively be introduced
into the
eductor in an aqueous medium such as the motive fluids referred to above. In
yet
another alternative, the particles 310 may be introduced into the eductor from
a
pressurized vessel including the particles 310 in a gas such as air, nitrogen,
propane, or any other suitable gas.
[0074] Thus, in the present example, the particles may be
introduced into the
boiler feed water without a pressurized gas while still providing turbulent
flow for
removal of the scale. Alternatively, a carrier solution for introduction of
the
particles 310 into the boiler feed water is optional as the particles 310 may
be
introduced utilizing a gas through the eductor 606.
[0075] During the scale removal process, fluid from the steam
generator 304
does not flow to the steam separator 316. Instead, the fluid 314, including
the
scale and particles 310, from the steam generator 304 is directed to, for
example, a
blowdown pond or other disposal site 440.
[0076] The remaining elements of the present example are
similar to those
described with reference to FIG. 4 and are therefore not further described
herein.
[0077] In each of the examples described above the particles
along with the
feed water may be introduced into the steam generator for removal of the scale
at
any suitable temperature. For example, the particles along with the feed water
may be introduced at a temperature of about 5 C to greater than 180 C. The
feed
water may already be at or near a temperature of about 180 C . The temperature
of the particles and feed water may be in the range of about 100 C to about
180 C
and the temperature may increase slightly in the steam generator as a result
of
residual heating. Optionally, the particles along with the feed water may be
introduced into the steam generator at a temperature as low as 5 C for removal
of
the scale, however. The use of feed water below about 50 C or above about 150
C
may facilitate scale removal by causing cracking of the scale as a result of
differing
thermal expansion rate of the scale compared to the thermal expansion rate of
the
metal tubes. Such cracks may facilitate removal by the fluidized particles.
The use
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of an acid or base in addition to feed water and/or carrier solution in the
steam
generator above about 150 C may also facilitate removal as the acid or base
may
attack the scale boundaries.
[0078] Advantageously, the particles, such as metal cuttings,
chopped wire,
metal beads, ceramics, glass beads, or other suitable particles in the steam
generator 304 scour the internal walls of the tubes, thereby removing scale
that
would otherwise reduce heat transfer and decrease efficiency. Thus, pre-
treatment
of the feed water may be reduced. In addition, scale removal in the steam
generator may be carried out in a matter of hours utilizing the present
process,
reducing time and expense for removing scale by comparison to known methods of
operating a pig within the steam generator.
[0079] The described embodiments are to be considered in all
respects only
as illustrative and not restrictive. The scope of the claims should not be
limited by
the preferred embodiments set forth in the examples, but should be given the
broadest interpretation consistent with the description as a whole. All
changes that
come with meaning and range of equivalency of the claims are to be embraced
within their scope.
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